It is often desirable to increase the fracture surface area and/or modify the fluid flow pattern within a subterranean formation such as geothermal reservoirs, Engineered Geothermal Systems (EGS), or steam-flooded petroleum fields. Increases in surface area can be equated to increased rates of energy introduction/extraction. The conventional method of increasing surface area is through a hydraulic stimulation procedure wherein large volumes of water are injected at high flow rates over several days to create shear failure in tight fractures adjacent the wellbore which leads to an increase in permeability. However, fracturing is often non-uniform and one very permeable (high flow) fracture is created in combination with many smaller fractures each possessing low permeability. This creates a non-uniform flow process with reduced heat exchange capability because most of the injected fluid enters and flows through the highly permeable fracture. Greater heat exchange can be obtained efficiently if flow is more uniformly dispersed among fractures.
Unfortunately, additional stimulation tends to also further expand high flow fractures thus reducing the stimulation affect on smaller low flow fractures. Furthermore, as certain portions of the geothermal reservoir become depleted productivity can be compromised requiring either further stimulation and/or plugging of unproductive fractures.
Similarly, oil and gas field operators frequently inject steam into oil and gas bearing formations. The increased temperature can improve the “flowability” of the oil and is often used for extraction of very thick or heavy oils. In this process, steam often follows paths of minimal resistance, referred to as short-circuits, that are present or that develop over time. When these short-circuits are present, a disproportionate amount of steam is injected into these which frequently results in poor injection into and ultimately poor sweep efficiency and incomplete oil recovery from, other portions of the formation.
Currently, high flow fractures and/or unwanted fractures can be permanently or temporarily plugged using cement. Such approaches can be difficult to uniformly cure and control plugging and flow. Although somewhat effective, subsequent removal of the cement typically requires expensive drilling with a workover drill rig. Other approaches include the use of packers. These materials can become stuck in the wellbore thereby requiring expensive and time-consuming procedures, such as fishing, to remove the obstructions. Sometimes fishing is unsuccessful and side-track drilling or other approaches become needed in order to restore wellbore function. Other systems for plugging these high-flow or unwanted fractures, such as precipitation of sodium silicate, can result in plugging of the formation that cannot be subsequently removed due to the insoluble nature of the precipitate. Further, such systems frequently require extended periods of down-time which can reduce productivity and increase costs.